Field of the Invention
This invention relates broadly to evaluating hydrocarbon trapped in the pores of an underground formation. More particularly, this invention relates to obtaining and evaluating hydrocarbon samples with a coring tool.
State of the Art
“Heavy oil” or “extra heavy oil” are terms of art used to describe very viscous crude oil as compared to “light crude oil”. Large quantities of heavy oil can be found in the Americas, in particular, Canada, Venezuela, and California. Historically, heavy oil was less desirable than light oil. The viscosity of the heavy oil makes production very difficult. Heavy oil also contains contaminants and/or many compounds which make refinement more complicated. Recently, advanced production techniques and the rising price of light crude oil have made production and refining of heavy oil economically feasible.
Heavy oil actually encompasses a wide variety of very viscous crude oils. Medium heavy oil generally has a density of 903 to 906 kg·m−3, an API (American Petroleum Institute) gravity of 25° to 18°, and a viscosity of 10 to 100 mPa·s. It is a mobile fluid at reservoir conditions and may be extracted using for example cold heavy oil production with sand (CHOPS). Extra heavy oil generally has a density of 933 to 1,021 kg·m−3, an API gravity of 20° to 7°, and a viscosity of 100 to 10,000 mPa·s. It is a fluid that can be mobilized at reservoir conditions and may be extracted using heat injection techniques, such as cyclic steam stimulation, steam floods, and steam assisted gravity drainage (SAGD) or solvent injection techniques such as vapor assisted extraction (VAPEX). Tar sands, bitumen, and oil shale generally have a density of 985 to 1,021 kg·m−3, an API gravity of 12° to 7°, and a viscosity in excess of 10,000 mPa·s. They are not mobile fluids where the formation temperature is approximately 10° C. (in Canada), and must be extracted by mining. Hydrocarbons with similar densities and API gravities, but with viscosities less than 10,000 mPa·s can be partially mobile where the formation temperature is approximately 50° C. (in Venezuela).
From this discussion, it becomes apparent that production techniques may vary significantly depending, amongst other things, on the density or API gravity of the oil, and its viscosity. Thus, knowledge of the composition or the physical properties of heavy oils would provide valuable insight as to the viability of various production strategies that might be utilized to extract heavy oil and/or bitumen from the formation. Therefore, it would be desirable to obtain a sample of the formation oil, with or without solid suspension (mostly sand) and preferably without drilling fluid, in order to gain this knowledge. If a sample is available, it may be analyzed uphole or downhole and a production strategy may be derived from the results of this analysis.
In the past, sampling tools, such as described in U.S. Pat. Nos. 4,860,581 and 4,936,139 have been proposed for taking samples of formation fluid. In the case of light oil, formation fluids are sampled by delivering a tool downhole and simply extracting formation fluid by applying a pressure differential to the formation wall. However, heavy oil may not easily be sampled in this way, as explained in further details below.
Indeed, the efficiency of fluid sampling as performed with conventional sampling tools depends usually on the rate of fluid flow from formation rock. More specifically, the flow rate Q of fluid from formation rock is given by Equation 1 where Δp is the pressure difference applied by the sampling tool, k is the permeability of the formation, and η is the fluid viscosity.Q∝Δp·k/η  (1)
As seen from Equation 1, the flow rate can be increased by increasing the pressure difference or the permeability or by decreasing the viscosity. The magnitude of the pressure difference is limited by the sampling tool (a maximum of approximately 50 MPa) and the consolidation of the formation, i.e. how large a pressure difference can be maintained before the formation collapses. In addition, other than fracturing and/or acidizing the formation, there is not much that can be done to increase the permeability. A possible method of sampling heavy oil would be to increase the hydrocarbon mobility by injecting a solvent. However, this might be unpractical when the solvent can not diffuse in the oil.
Furthermore, even if a representative sample were obtained downhole, bringing it uphole could cause an unknown change in the physical characteristics of the sample. Because of the environment in which heavy oil and bitumen are found, samples taken downhole can change when brought to the surface for analysis. Such changes include the evaporation of potentially volatile components such as methane, ethane, and propane; the precipitation of waxes or asphaltenes; the contamination by wellbore fluids; etc.
From the foregoing it will be appreciated that there are many challenges to obtaining and analyzing representative formation hydrocarbon samples when these hydrocarbons have a very low mobility.